1. Field of the Invention
Embodiments of the invention generally relate to flow analysis for hydrocarbon production and, more particularly, to flow rate analysis in a multiphase fluid in the presence of a hydrate inhibitor.
2. Description of the Related Art
Oil and/or gas operators periodically measure water/oil/gas phase fractions (relative concentrations) of an overall production fluid flow in order to aid in optimizing well production, allocating royalties, inhibiting corrosion/hydrates (e.g., based on the amount of water), and generally determining the well's performance. Multiphase metering is desired for measuring individual well production of oil, water, and gas. In subsea applications, since many production systems involve commingling of multiple wells prior to the riser, subsea multiphase metering may be the only option to get individual well rates other than a measure-by-difference technique.
Various approaches for analyzing the phase fraction of such fluid flows exist and include full or partial phase separation and sensors based on capacitance, density and microwave measurements. However, known measurement techniques suffer from their own unique drawbacks and/or limitations, such as frequent calibrations, as well as sensitivity to salinity, gas, and emulsions. In addition, current subsea multiphase meters can be prohibitively expensive.
Water in gas wells introduces the prospect of hydrate formation that may impede or plug the flow and create unsafe flowing conditions. Hydrates are ice-like crystals of water and hydrocarbon (or carbon dioxide, etc.) that form at low temperatures and high pressures common in subsea applications.
Furthermore, gas wells that have a high flow rate may produce large pressure drops across chokes and other flow-area changes. At these locations, Joule-Thomson cooling can reduce temperatures significantly, which may result in severe hydrate problems in a matter of hours or even minutes if water is present. Serious problems result once the hydrates form and block or limit flow. Hence, most flow assurance methodologies are aimed at prevention of hydrate formation.
Some approaches utilize chemical injection to inhibit gas hydrate formation. However, cleaning and treatment procedures required at the surface to remove the hydrate inhibitor along with high costs of the inhibitor itself may contribute to production expenses. Therefore, injection of methanol, as an exemplary hydrate inhibitor, increases costs when done at levels beyond that required based on the water that is present. Known measurement techniques are not well-suited to make low water measurements especially when the fluid flow is further complicated by the hydrate inhibitor injection.
Therefore, there exists a need for an improved infrared optical detector and overall phase fraction measurement to enable, for example, flow assurance with improved sensitivity and accuracy, improved reservoir management, and improved allocation from a producing well. Accordingly, techniques and systems for determining the flow rates of components of a multiphase fluid containing a hydrate inhibitor are desirable.